1. Field of the Invention
This invention concerns drill stem threaded connections in general. In particular the invention is for a tool joint and a resulting drill string where the tool joint connects drill pipe sections and other elements of the drill stem together from the surface to the drill bit. Still more particularly, this invention is for a tool joint having internal and external make-up shoulders for high torque application of rotary drilling.
2. Description of Prior Art
Deep wells such as for oil and gas are drilled with a rotary drill bit rotated by a drill stem which consists of a bottomhole assembly, a string of drill pipe, a kelly or top drive, and all associated equipment in the rotating string to the drill bit. The drill pipe string is made-up of individual members, each about 30 feet in length. The drill pipe members are secured together by a threaded connection, called a tool joint, typically about 1½ feet long. The tool joints must withstand the normal torque encountered during drilling, and also provide sealing to prevent drilling fluid being pumped down the drill pipe from leaking out the joints. Leakage out of the tool joints causes wear due to the abrasiveness of the drilling fluid, which can lead to early failure.
A conventional tool joint (sometimes called an API [American Petroleum Institute] tool joint) is made-up of a pin member and a box member. The pin member has external threads and an external annular make-up shoulder. The box member has internal threads and a rim or face that makes up against the make-up shoulder. In a conventional tool joint there is no internal shoulder in the box member for contact by the nose or face on the end of the pin. When the tool joint members are made-up at the surface of the well, normally they are made-up to a torque that creates a longitudinal stress in the threaded cross section that is about one-half the yield strength of the weaker of the pin or box.
In drilling horizontal or extended reach wells or when the drill string gets stuck in the borehole, it is possible for drilling torque to exceed the make-up torque, applied at the surface of the well. When the drilling torque exceeds the surface make-up torque, additional connection make-up torque occurs. The additional make-up torque imparts higher stresses in the connection which may exceed the yield strength of the pin and box and cause downhole failure. To avoid the possibility of failure, the surface make-up torque should be higher than the drilling torque. Consequently the drill pipe tool joint industry has developed so called “double shoulder tool joints” that have higher torque strength characteristics than API tool joints, allowing higher surface make-up torque. Double shoulder tool joints have not only an external make-up shoulder, but also an internal make-up shoulder and dimensions that cause both shoulders to make up under high torque conditions.
As shown in U.S. Pat. No. 2,532,632, double shoulder tool joints have not only an external make-up shoulder, but an internal make-up shoulder and dimensions that cause both shoulders to make-up under high torque conditions. A double shoulder tool joint can have a substantially increased torsional yield strength (as compared to an API tool joint) without any additional thickness in the pin or box, and without increasing the yield strength of the steel.
The prior art has strived to achieve better and better operating characteristics for a double shoulder tool joint by adjusting dimensions of elements that characterize such a joint. Such elements include the relative lengths of the box counterbore, pin base, the pin nose, and the threads; the relative cross sectional thickness of the box counterbore and the pin nose; and the relative dimensions of the tool joint inner and outer diameters.
A double shouldered connection is also described in U.S. Pat. No. 4,558,431. The box is provided with an internal shoulder located below its threads. The pin has a face on the end of its nose that mates with the internal shoulder in the box. The dimensions of the pin and box are selected so that when hand tightened, the box face contacts the external shoulder of the pin. A clearance exists between the pin nose face and the internal shoulder of the box. When the tool joint is fully made-up to its normal make-up torque, the box face engages the external make-up shoulder to the normal contact pressure. A hand tight clearance is selected such that the pin face exerts little or no pressure against the internal shoulder at normal make-up torque.
The above mentioned U.S. Pat. No. 4,548,431 specifies that the pin base and box counterbore sections have a length at least one-third the length of the engaged threads and that the pin nose should have a length at least one-sixth the length of the engaged threads. For the double shouldered tool joint, described in U.S. Pat. No. 4,548,431, with a 5″ OD and 2 11/16″ ID, the torque to yield the base section of the pin or the counterbore section of the box for a double shouldered joint is 25,583 foot pounds as compared to 18,100 foot pounds for an API tool joint with the same OD and ID. The long counterbore section lowers the resistance to deflection thereby allowing reasonable manufacturing tolerances for the hand tight clearance. However, the long counterbore section tends to buckle outward under high torque.
Others in the industry select the hand tight clearance such that the internal shoulder is substantially loaded at the designed surface make-up torque. Designed in this way, the internal shoulder allows a larger surface make-up torque and may therefore be safely used in wells which require a larger drilling torque. When the tool joint is tightened beyond the initial hand tight condition, the counterbore of the box and the pin base section deflect. This deflection allows the pin face to close the hand tight clearance and engage against the internal shoulder. The loading of the pin face and internal shoulder occurs prior to any permanent deformation occurring in the box counterbore and pin base sections.
Expanding the concept of having the internal shoulder loaded at surface make-up torque, U.S. Pat. No. 6,513,804 describes still another double shouldered tool joint design in which the internal shoulder makes up first, because the length from the pin external shoulder to the pin nose is greater than the length from the box face to the box internal shoulder. The pin nose is specified to be twice as long as the box counterbore. Having the internal shoulder contact before the external shoulder creates a risk that the external shoulder may not be sufficiently loaded to effect a seal. The extra long pin nose attempts to overcome this risk by lowering the nose resistance to deflection.
U.S. Pat. No. 5,492,375 describes another design of a double shoulder tool joint with an emphasis on optimizing the torsional strength of a double shouldered connection. The optimization is achieved by assuring that under high torque conditions, the threads are very close to, but not quite at failure in shear prior to yielding of the pin nose and box counterbore or pin base. U.S. Pat. No. 5,492,375 specifies that the length of the engaged threaded section of the pin, which determines the shear area of the threads be such that At is equal to or only slightly greater than 1.73(AL+AN) where AL is the lesser of the cross-sectional area of the pin base or of the box counterbore and AN is the cross-sectional area of the pin nose. Optimization by this technique provides only small increases in connection torsional strength.
U.S. Pat. No. 5,908,212 describes another double shoulder tool joint design by requiring (1) that the sum of the cross-sectional area of the box counterbore, plus the cross-sectional area of the pin nose be at least 70% of the cross-sectional area of the box, (2) that the taper of the threads be less than one inch per foot, and (3) that the counterbore section axial length be at least 1.5 inches.
A shallow thread taper dramatically increases the strength of the internal shoulder and therefore increases the torsional strength of the connection. However, drill pipe joints with shallow thread tapers require substantially more rotations of the pin with the box during make up, as compared to conventional API tool joints. The additional rig time required to make-up these connections is very expensive and undesirable. The shallow taper also makes connection stabbing and unstabbing more difficult, because the connection must be carefully aligned to avoid thread interference and galling. Further, the shallow taper requires a large loss of the limited tool joint length when the connection is re-machined after wear or damage.
The prior art joints also provide conventional thread form designs which inhibit optimum yield torque characteristics for pipe joints generally and in particular for double shoulder drill pipe joints.
The prior art tool joints are also characterized by a thread form with a crest taper that matches the taper of the threads. FIG. 5 of the attached drawings illustrates a prior art thread form where the taper of the crest 41 is the same as the overall taper Tth of the threads. A thread form in general is characterized by a thread root 39, a load flank 35, a crest 41, a crest-load radius 43, a crest-stab radius 45 and a stab flank 33. When stabbing elements of the drill pipe joint (i.e., stabbing a pin into a box), it is inevitable that crests of one element will occasionally come to rest on the thread crests of the other. FIGS. 6A, 6B and 6C illustrate a prior art pin 5 and box 5′ being stabbed together with FIGS. 6B and 6C showing cross sections of the threads of the pin 5 and box 5′. FIG. 6B shows the crests 41 of the pin 5 resting on the thread crests 41′ of the box 5′. As FIG. 6C shows, a rotation of up to about one-half turn is required to move pin 5 axially with respect to box 5′ to get past crest 41-crest 41′ contact and cause stab flank 33-stab flank 33′ contact. If crest to crest contact occurs with an impact, the load flanks 36, 36′, stab flanks 33, 33′, or both can be permanently damaged near the crests 41, 41′, especially because of the small crest to load flank and crest to stab flank radii typically found in conventional tool joints. Even if damage does not occur on stabbing, the pin tool joint crests 41 can wedge into the box tool joint 5′. Such wedging action is exacerbated by the impact. As the thread taper is reduced, the wedging action gets worse. For a friction factor of 0.08, the thread crests 41, 41′ are self-holding for thread tapers less than 2″/ft. Self-holding means that the tool joints must be forcibly separated. Forcing the threads past wedging of the thread crests can eventually lead to galling and other damage.
3. Identification of Objects of the Invention
A primary object of the invention is to provide a drill stem connection, in particular for a drill pipe tool joint with enhanced yield torque characteristics.
Another object of the invention is to provide a drill pipe tool joint with enhanced yield torque characteristics while simultaneously having a make-up turns characteristic of a conventional API tool joint.
A specific objective of the invention is to provide a drill pipe tool joint that is characterized by a torsional strength that is at least about fifty percent or more than that of a conventional connection of comparable size and with make-up turns about the same as the conventional connection.
Another object of the invention is to provide a double shoulder drill pipe tool joint with an improved thread form in combination with an optimum thread taper such that enhanced torque characteristics result.
Another objective of the invention is to provide a tool joint with a thread design that provides enhanced stabbing characteristics when the pin is stabbed in the box during make up.
Another object of the invention is to provide a tool joint design with a box counterbore length shorter than or equal to the pin nose length in order to avoid box buckling.
Another object of the invention is to provide a tool joint design characterized by primary shoulder and secondary shoulder stresses being within a range of 70% of each other for optimization of load carrying ability within manufacturing tolerances.
Another object of the invention is to provide a thread form for tool joints where crest-to-crest wedging of threads while stabbing is substantially prevented.
Another object of the invention is to provide a thread form for tool joints that allows the pin threads to more easily center within the box threads while providing a more rugged shape with a more narrow crest without reducing the contact area of the load flank.
Another object of the invention is to provide a thread form which (1) provides a reduced stress concentration in the thread root while maximizing the contact area of the load flank and minimizing thread depth, (2) allows for larger critical areas at the primary and secondary shoulders of a double shoulder tool joint thereby providing increased torque capacity of the joint, and (3) reduces the probability of jamming the connection.
Another specific objective of the invention is to provide a double shoulder drill pipe tool joint characterized by pin nose and counterbore lengths such that stresses at the primary and secondary shoulders increase at a similar rate as connection torque increases are applied to the connection.
Another object of the invention is to provide a tool joint with an enhanced wall thickness opposite the threads in order to provide greater connection strength.